Saturday, January 07, 2012

Thanks to the Oil and Gas Boom, ND, AK and TX Have Regained All Jobs Lost During Recession

Despite the gradual improvements in the U.S. labor market and the drop in the jobless rate to 8.5% in December, the payroll employment level of 131.9 million jobs in December is still more than six million jobs below the 137.9 million peak level when the recession started in December 2007. In percentage terms, December payrolls were 4.5% below the December 2007 level, see the chart above.

In contrast to the ongoing "jobless recovery" at the national level, there are three states that have now regained all of the jobs lost during the recession: North Dakota, Alaska and Texas (see chart above). What do these three states have in common? They are all oil and gas rich, and have been adding thousands of mining and natural resources jobs over the last several years (12,000 in North Dakota, 2,200 in Alaska and 66,600 in Texas) to keep up with the increased domestic production of energy resources, mostly for shale gas and oil.

16 Comments:

Thus, while Obama claims credit for a reduction in the unemployment rate, at least part of it is due to an increase in oil and gas development and production which he has done everything in his power to thwart.

Where's VangeIV (or whatever his handle is) to tell us that the oil will run out,...

I have never said that oil will run out. I have simply pointed out that we are at peak production and that shale won't change any of that. A good conventional well produces more than 25,000 barrels a day for many years. A poor well will produce more than 1,000 barrels per day for many years. A typical shale well averages less than 100 barres a day after three years. You need about forty to fifty of those to get the same type of production as one typical conventional well.

...it's all a scam,

It is a big scam so far. We see the typical well costing $5 million to $7 million but see its production down to less than 100 bpd within two years because of the very high depletion rate. That means that you are not going to generate much of a return from shale oil and gas and even if you don't mind chewing through capital you will not be able to offset depletion of conventional wells in Alaska, the Gulf, and elsewhere. As for foreign production, all of the great fields are now in decline. Given the fact that they produce most of the world's cheap oil prices will have only one way to go in the absence of an economic contraction that destroys demand.

...and it's unprofitable to drill for it anyway?

That may not be true. While you can't make money from production you can certainly make money by selling properties to majors who don't need production as much as they need cover for their collapse of reserves. The SEC makes it very easy for these companies to use shale properties to overstate reserves. As I have written before, if the US ever adopts the equivalent of Canada's NI 43-101 standard you better short all shale players plus the majors who have shale reserves.

"You're right the oil will never run out. Only an idiot would worry about oil supplies, pollution from oil products or global warming"...

El culito says it best...

Funny he kind sounds like Al Gore...

New York state will not soil itself with the vile and despicable profits wrung from oil and gas...

"The Empire State faces a $3 billion budget gap for fiscal year 2013. According to State Budget Solutions, a nonpartisan think tank, New York’s deficits, long-term debt, and pension obligations total $305 billion. High taxes, unemployment, and a burdensome cost of living make New York Number One in emigration to other states"...

VangelV, you are the textbook case of a little knowledge being a dangerous thing. You should be stripped of all Google privileges.

I won't pretend to be an expert on North Dakota, but I would qualify as an expert on oilfield economics.

At $5-7 million per well (your number), it takes somewhere in the neighborhood of 100- to 150,000 barrels of oil to pay out the cost (after royalties, taxes, lease operating expenses, etc.)

After that, 100 barrels per day is not bad.

Your assertion ("A good conventional well produces more than 25,000 barrels a day for many years. A poor well will produce more than 1,000 barrels per day for many years.") is flat-out absurd. Are you talking about the Gulf of Mexico deepwater, where the cost per well runs into hundreds of millions of dollars? Or are you talking about the Middle East? Because wells with those kinds of producing rates are anything but common, and completely unheard-of in the onshore U.S.

As a rule-of-thumb, 100,000 barrels (not per day, but total production in its life) is usually a pretty decent onshore U.S. oil well. Of course, "how good" all depends on cost.

At $5-7 million per well (your number), it takes somewhere in the neighborhood of 100- to 150,000 barrels of oil to pay out the cost (after royalties, taxes, lease operating expenses, etc.)

The problem is that many wells do not get to that number. Depletion runs at more than 75% per year and you are lucky to be getting 350 bpd by the end of the second month. Many wells are idled after the third or fourth year because the lifting cost cannot justify the output.

The trick is to ignore all the hype and to pay attention to the actual results that were reported. From what I see, the shale gas producers got killed as they could not make a profit at anywhere near the current price levels. (That means that Mark's claims that we are about to have cheap AND abundant gas cannot be true. If gas stays cheap the companies will stop taking losses and will reduce their drilling activity even if they have to lose some of their leases. If they do drill it will mean that gas has gone up in price substantially while other costs have remained stable.)

On the oil front there aren't that many producers who have operated long enough to make a call one way or another. I think that there is a lot of money to be made by a company that is focused only on core areas of the best formations. The problem with that is that such areas are not abundant and, as we have seen with the Elm Coulee field in Montana, have a very limited life. I suggest that all those who want to know what the future for shale will be like need to take a a look at Montana. Not long ago people were hyping Montana as a great producer with abundant shale reserves. Now that reality has intervened people are ignoring its production trends and are hyping up the next great oil and gas province.

Your assertion ("A good conventional well produces more than 25,000 barrels a day for many years. A poor well will produce more than 1,000 barrels per day for many years.") is flat-out absurd. Are you talking about the Gulf of Mexico deepwater, where the cost per well runs into hundreds of millions of dollars? Or are you talking about the Middle East? Because wells with those kinds of producing rates are anything but common, and completely unheard-of in the onshore U.S.

Not at all. I am talking about your typical conventional wells when the US was on the other side of Hubbard's Peak. American wells used to be very productive and very cheap to drill. The fact that people are excited about 100 bpd of production from wells that cost $5-$7 million shows us just how much of the low hanging fruit has already been picked.

Sorry about that. I was arguing against some of my AGW pals and used data on global sea ice cover the Hubbard glacier's growth to show that things are not exactly as they say. It must have been on my mind when I was thinking of Hubbert, about whom I have written many times before.

I am well aware of Dr. Hubbert's work and have read more than a dozen books by Matt Simmons, Kenneth Deffeyes, Colin Campbell, Richard Heinberg, Michael Economides, Daniel Yergin, Robert L. Hirsch, etc., on the subject. From what I have seen the Hubbert methodology is very sound and even if you apply the new technologies and new frontiers to the existing data you will not push out the global peak date very far.

Second, 25,000 barrel per day wells are not and never have been commonplace in the onshore U.S. A well like that would make one million barrels in a little over a month.

As Matt Simmons and Kenneth Deffeyes have pointed out, a high rate of production was easy in the days when US production was growing. But most producers were content with shallow wells that were cheap to drill and could produce for many years without worry about depletion. Producers controlled rates of production because they did not want to push the wells too hard. The goal was to optimize ultimate production, not maximize it over the short term.

Many producers were very careful to turn down the flow rates and carefully control the production for years. Depletion was not a serious issue and a well that was cheap to drill but put out 3,000 bpd could keep producing near that rate for five to ten years. Such a well could produce more than 10,000 bpd if the producer were willing to spend more money but there was no need to because a high rate was not good for the ultimate recovery figures.

In one of the interviews on FSN an energy analyst pointed out that a long horizontal well in a conventional field in the pre-peak period could easily produce more than 100,000 bpd but at a cost of high depletion and a lower UR figure.

Really? Show me the positive cash flows for shale producers that have been in business for a number of years. If shale gas and oil were such a good investment they should be self financing. But it isn't a good investment and most of the conference calls that I listen to are full of references to asset sales and funding gaps.

The big red flag for the sector should be Chesapeake. Aubrey McClendon bet the farm on shale gas early in the game when core areas were very productive and prices were high. He even hedged production to ensure that he was protected by a downturn in prices. The market loved his company so much that he became one of the higher paying CEOs and wound up with a compensation package that ran into the many millions including a year during which he got more than $100 million. He was a believer and put his money where his mouth was. But when the correction came he had to sell his shares at $17 to meet a margin call. Those shares had been selling for more than $70 just a few months previously.

Since them Chesapeake has been bleeding red ink. It has sold some properties to raise financing and has used many credit lines and facilities to stay in business. And after nearly a decade of hyping shale gas the company is now promising a transition to shale liquids. But there is absolutely no evidence that its newest efforts will turn out any better than the previous ones. While oil prices are more stable and there is downside protection due to the 6% depletion of conventional fields the company has a 75%-90% depletion in its own very expensive wells.

I, however, am not. You can visit the 'About' page at my blog to check out my credentials.

I do not doubt your credentials. I doubt your conclusions. After all, as I pointed out above, Aubrey was a very qualified person who was a true believer in shale gas. Yet he managed to lose almost two billion of his wealth on a lousy bet that had little chance of success.

I have no problem staying apart from the herd on this or any other issue because the facts that matter are on my side.

I don't know who changed the subject to the long-term viability of the shale gas plays, but it wasn't me.

I am very happy that you have READ TWELVE BOOKS on the subject, but you should stick with what you read, and not make stuff up out of whole cloth.

A well that makes 3,000 barrels a day for 10 years - while being rate-constrained! - would make almost 11,000,000 barrels. Quite an exceptional well. I'd like to see documentation of it.

For your information, most of the producing *states* (not companies) imposed rate restriction schemes, called proration or "allowables", from the '30s (?) on into the early '70s or so.

A typical well in Texas, for example, would have been allowed to produce & sell 240 barrels per day, even if it could physically make more.

As for the viability of the shale plays, it is in the eye of the beholder. My company has not chosen that route. Chesapeake made a large bet on it in 2008 with gas prices about 4x what they are now. They have successfully sold down their participation in the Haynesville, Marcellus, Utica and others, and not at bargain-basement prices. Most recently, Petrohawk (mostly Haynesville) sold out to BHP Billiton for something like $7 billion IIRC, so they have made money. Maybe you should contact BHP and tell them about the books you've read.

I don't know who changed the subject to the long-term viability of the shale gas plays, but it wasn't me.

Well, given the fact that shale production is not viable over the short term what else is there left to talk about?

I am very happy that you have READ TWELVE BOOKS on the subject, but you should stick with what you read, and not make stuff up out of whole cloth.

I am an engineer by training and an investor in energy and other commodity plays. I talk to geologists, engineers, and CEOs on a regular basis so spare me the crap. On one of the talks that I attended a geologist pointed out the big difference with a direct comparison between wells and fields developed in the past versus today.

He stated that when his father used to drill in Texas the wells were vertical and very shallow. The economics dictated that you drill your well and get your few hundred barrels per day out. The same area today would yield hundreds of thousands of barrels per day if it used the expensive horizontal wells that the shale producers are using today. No expensive fracking would be required and the depletion rate would not run to the 75-90% per year as many current shale wells do. The drillers certainly had little interest in natural gas because it was too cheap to sell. As a result, flaring was common in many areas of the world.

The bottom line was the energy return on the energy invested. Those shallow wells returned more than 100:1. The wells today would be lucky to get a 2:1 return.

As for the viability of the shale plays, it is in the eye of the beholder.

Now this is where the argument gets interesting. The same could be said to be true of the shares of Nortel or Pets.com. If you don't care about operational profits and are hoping to find a bigger fool to dump your overvalued shares to than it makes sense to speculate even if you know that there is a bubble that has to burst eventually.

But that is not my concern. On this thread the argument being made is that shale is a long term solution to the American energy problem because shale production is economic using current methodology.

My company has not chosen that route. Chesapeake made a large bet on it in 2008 with gas prices about 4x what they are now.

Chesapeake has lost money in shale gas production even though it has hedged at much higher prices. It cannot self finance from operations and must sell itself off in pieces or borrow more to drill off its shale properties. Management knows this, which is the reason it is trying to argue that it will reposition the company to a shale liquids play.

They have successfully sold down their participation in the Haynesville, Marcellus, Utica and others, and not at bargain-basement prices. Most recently, Petrohawk (mostly Haynesville) sold out to BHP Billiton for something like $7 billion IIRC, so they have made money. Maybe you should contact BHP and tell them about the books you've read.

That is my point. The companies failed to make a profit from production and ran into financing issues that could only be resolved by finding a bigger fool.

That said, I do not believe that conventional producers are making a mistake by buying operationally worthless shale properties. Since there is no NI 43-101 equivalent in the US the shale drillers can overestimate their reserves. And since the reported boe reserves can use the 6:1 conversion rate rather than the more appropriate 30:1 rate a conventional producer can hide reserve declines by paying up for shale properties. Since that allows the share prices to stay up the acquiring producer can use its share price as currency to purchase smaller players who have undervalued reserves. This turns out to be a game of financial engineering that has little to do with production.